In deep- and ultra-deep-water oil and gas exploration, crude oil or gas is extracted from below the sea floor via a pipeline system to the water surface. It is important to maintain the temperature of the hot crude oil or gas flowing in the pipe above about 30–50° C. depending on the composition of the hydrocarbons (e.g., crude oil or natural gas). Maintaining a temperature in this range prevents flow restrictions or clogging due to formation of hydrates or wax, which can occur via cooling of the crude oil or gas by cold water as the hydrocarbons flow from the underwater well to the production plant on the surface. Also, if the well must be capped for maintenance or due to inclement weather, it is highly desired to keep the temperature of the hydrocarbon inside the pipe and other parts of the pipeline systems (e.g., a Christmas tree or subsea tree, risers, etc.) above precipitation temperature for as long as possible to minimize or avoid expensive and time-consuming de-clogging processes before resuming the pumping operation.
These are the so-called flow assurance requirements for the underwater pipe-in-pipe configuration. The pipe-in-pipe configuration has been the traditional method of choice to satisfy the flow assurance requirements of the deep-water exploration. The configuration uses two thick concentric pipes; i.e., the inner pipe (flow line or flow pipe) and the outer pipe (carrier pipe). The flow line carries the hydrocarbon coming out of the well at high temperature (e.g., 60–300° C.) and at high pressure [e.g., up to about 70 MPa (10,000 psi)]. The carrier pipe is designed (independent of the flow line) to withstand the external hydrostatic pressure that proportionately increases with depth [e.g., about 28 MPa (4000 psi) at 2800 m].
In the annulus between the two pipes, split-ring spacers (also referred to as “centralizers”), which are made of a material having relatively low conductivity (e.g., a polyamide), are installed at regular intervals (e.g., at 1.2-m intervals). The spacers act as a guide during the insertion of the inner pipe into the outer pipe; each pipe can be 1 or 2 km in length.
The spacers are also designed to help maintain the annular gap between the two concentric pipes when the pipe-in-pipe apparatus is bent for winding onto a spool or when it bends after installation. In the annular gap between the spacers, insulation material is wrapped around the flow line. The insulation material can be, e.g., a urethane foam having a thermal conductivity of 24 mW/m-K and higher or a fumed silica product packaged in vacuum with thermal conductivity of 21 mW/m-K.
In some locales, the temperature of the crude oil coming out of the well is only 60° C., which is not very hot, as is the case off the coast of Angola. As a consequence of this relatively low temperature, a much higher level of insulation is needed to prevent hydrate formation due to cool down. Also, as the recoverable oil and gas deposits in the shallow sea bottom are exhausted, the wells will be drilled in increasingly deeper waters. The current pipe-in-pipe design, while acceptable down to a depth of 1000 m, meets severe obstacles when the underwater field gets much deeper than 1000 m, as described below.
As the well depth increases, the following obstacles and technical issues have to be overcome. As a starting point, the characteristics of hydrocarbons become more prone to forming wax or hydrates. Additionally, since the distances between the deeper wells and the production plant on the surface platform are significantly increased, the overall-heat-transfer (OHT) value of the pipe-in-pipe apparatus must ordinarily be reduced to very low values, such as 0.5 W/m2-° C. with a transient cooling requirement of less than 30° C. in 16 hours, to prevent over-cooling of the recovered hydrocarbons. Providing a pipe-in-pipe apparatus with this very-low OHT value would ordinarily necessitate significantly increasing the thickness of insulation, which in turn would increase the inner diameter of the carrier pipe needed to accommodate the additional insulation contained within the carrier pipe.
As the inner diameter of the carrier pipe increases, the carrier-pipe wall thickness that is needed to withstand a fixed external pressure in this context increases as an approximately proportional function of the increase in the outer diameter of the carrier pipe. Moreover, as the depth increases, the external pressure acting upon the carrier pipe increases as a linear function of the depth. For each 10.33 m of water depth, pressure increases by 1 atm (100 kPa). At 2500 m, the hydrostatic pressure reaches about 25 Mpa (3560 psi). The thickness of the carrier pipe wall is increased approximately proportionally with an increase in the hydrostatic pressure for a given inner radius. Therefore, the carrier pipe wall is fabricated with increasing thickness as the pressure for the intended usage is increased, which causes further increase in the outer diameter of the carrier pipe as the intended usage depth increases.
As the carrier pipe gets larger in diameter and in thickness, the following disadvantages result. First, the weight of the pipe-in-pipe apparatus increases sharply, increasing approximately proportionally with the square of the wall thickness and linearly with the mean diameter. Second, the material cost increases as the amount of steel and insulation increases. Third, additional labor and heavier equipment is needed to produce the pipe-in-pipe apparatus. Fourth, heavier equipment is needed to wind the pipe-in-pipe apparatus onto a spool and also to install the pipe-in-pipe apparatus; the equipment that is currently used may need to be reinforced and strengthened (at a significant level of capital expenditure) to handle the much heavier pipes that would be required for depths of 2500 m and deeper. Fifth, the submerged weight of the pipes can become too heavy for the currently used derricks or ships to handle the load and keep it stable in rough seas; the excess weight of the pipes accordingly necessitates building larger derricks, ships and larger buoyancy tanks at increased costs and decreased stability in the rough waters. Finally, the ship must make more trips to transport the necessary pipe lengths.
The current pipe-in-pipe manufacturing operation is extremely labor intensive and therefore costly. The pipes used for flow lines and carrier pipes generally come in 12-m (40-ft) lengths from the supplier. At the factory, the 12-m long pipes are first welded together into 1- or 2-km long sections of the outer carrier pipe. Section by section, polyamide spacers (centralizers) are installed onto the inner flow-line sections and thermal insulation is wrapped around the flow-line sections between the centralizers. After each flow-line section is insulated and secured by strapping with tapes, that section will be pushed into a waiting carrier pipe. The next section of the flow line is welded to the section to be inserted into the carrier pipe. The centralizers help guide the flow line during insertion into the carrier pipe. This process continues until the full length of the 1-km or 2-km pipe-in-pipe apparatus is assembled. The processes of welding the pipes and installing the centralizer and thermal insulation occur in stop-and-start fashion and require substantial manual labor and time.
In an alternative method currently used, the entire 1- or 2-km sections of the flow line and the carrier pipe are welded separately. Then, the entire length of the flow line is fitted with centralizer rings at regular intervals and with thermal insulation between the centralizers, and covered and fastened in place with tapes. The completed insulated flow line is then carefully inserted into the waiting carrier pipe relying on the centralizers to maintain the annular gap and thus protect the insulation during the insertion operation.
For the reasons discussed above, when the depth increases significantly for the underwater pipeline, it will become more economically and logistically unacceptable to continue to use the current design of pipe-in-pipe apparatus, insulation material, and manufacturing process. Both manufacturing methods described above represent the state-of-the art pipe-in-pipe manufacturing process and are very labor intensive, costly and slow.
In one recent pipe-in-pipe design, the inner flow line is covered with non-load-bearing insulation protected by a carrier pipe made of Glass Reinforced Plastic (GRP). The GRP pipe is connected mechanically to the flow line at both ends of a 12-m long pipe section using mechanical joints comprising a load-bearing polymeric material able to guarantee the thermal and mechanical performances. A relatively high-performance, but non-load-bearing insulating material with thermal conductivity of approximately 21 mW/m-K fills the annular space between the flow line and carrier pipe and provides the required thermal performances. The authors describe how much lighter this new pipe would be compared to the current pipe-in-pipe design and how much more conveniently the pipe could be produced in an automated process. Although the submerged weight of this new configuration may be less than that of a conventional pipe-in-pipe apparatus designed for the same operating conditions, the ability of the fiberglass to withstand the seawater conditions on a long-term basis is unproven, and the outer layer remains extremely thick. Therefore, the GRP pipe may not have the necessary bending flexibility, and, as a consequence, additional trips may be needed to carry the larger diameter pipes to installation sites.
In the conventional pipe-in-pipe design and also in the GRP pipe-in-pipe design, described above, the inner pipe is designed to withstand the usually high inner pressure [e.g., 70 Mpa (10,000 psi)], and the outer pipe is designed to independently withstand the external crushing pressure [15 Mpa (2170 psi) at 1.5 km (5000 ft) and 30 Mpa (4340 psi) at 3 km (10,000 ft)].